Method and apparatus for liquefying a hydrocarbon stream

ABSTRACT

A method and apparatus for liquefying a hydrocarbon stream ( 10 ) such as natural gas. The method comprises the steps of: (a) compressing the hydrocarbon stream ( 10 ) using one or more compressors ( 12 ) driven by one or more steam turbines ( 14 ) to provide a compressed hydrocarbon stream ( 20 ); (b) heat exchanging the compressed hydrocarbon stream ( 20 ) against one or more refrigerant streams ( 40 ) to fully condense the compressed hydrocarbon stream ( 20 ) and provide a liquefied hydrocarbon stream ( 30 ) and one or more warmed refrigerant streams ( 50 ); (c) compressing at least one of the warmed refrigerant stream(s) ( 50 ) of step (b) using one or more compressors ( 18 ) driven by one or more gas turbines ( 22 ); and (d) at least partly driving one or more of the steam turbines ( 14 ) of step (a) using steam provided by one or more of the gas turbines ( 22 ) of step (c).

The present invention relates to a method and apparatus for liquefying ahydrocarbon feed stream, such as a natural gas feed stream.

Several methods of liquefying a natural gas feed stream therebyobtaining liquefied natural gas (LNG) are known. It is desirable toliquefy a natural gas stream for a number of reasons. As an example,natural gas can be stored and transported over long distances morereadily as a liquid than in gaseous form, because it occupies a smallervolume and does not need to be stored at a high pressure.

Usually natural gas, comprising predominantly methane, enters an LNGplant at elevated pressures and is pre-treated to produce a purifiedfeed stock suitable for liquefaction at cryogenic temperatures. Thepurified gas is processed through a plurality of cooling stages usingheat exchangers to progressively reduce its temperature untilliquefaction is achieved. The liquid natural gas is then further cooledand expanded through one or more expansion stages to final atmosphericpressure suitable for storage and transportation. The flashed vapourfrom each expansion stage can be used as a source of plant fuel gas.

The costs in creating and running a liquefied natural gas (LNG) plant orsystem are naturally high, and a significant part is for the coolingconfigurations. Any reduction in the energy requirements of the plant orsystem has significant cost benefit. Reducing any cost of any coolingconfiguration is particularly advantageous.

The use of steam turbines for driving compressors for refrigerants isknown.

U.S. Pat. No. 6,389,844 B1 relates to a plant for liquefying naturalgas, more specifically, a pre-cooled dual heat exchanger, dualrefrigerant system. The plant in U.S. Pat. No. 6,389,844 B1 has aliquefaction capacity which is 40 to 60% higher than that of a singleliquefaction train, and comprises one pre-cooling heat exchanger, and atleast two main heat exchangers. Each liquefaction refrigerant circuituses a gas turbine-driven liquefaction refrigerant compressor, and thedriver of the compressor in the pre-cooling refrigerant circuit can be asteam turbine, wherein the steam required to drive the steam turbine canbe generated with heat released from the cooling of the exhausts of thegas turbines of the main refrigerant circuits.

A drawback of driving a compressor in a refrigerant cycle like in U.S.Pat. No. 6,389,844, is that variations in the amount of steam generatedby the cooling of the exhaust of the gas turbines could cause changes inrefrigeration capacity of the refrigerant cycle.

The present invention provides a method of liquefying a hydrocarbon feedstream, such as a natural gas feed stream. The method at least comprisesthe steps of:

-   -   heat exchanging a compressed hydrocarbon stream against one or        more refrigerant streams to fully condense the compressed        hydrocarbon stream and provide a liquefied hydrocarbon stream        and one or more warmed refrigerant streams;    -   compressing at least one of said one or more warmed refrigerant        stream(s) using one or more refrigerant compressors driven by        one or more gas turbines;    -   driving one or more compressor-driving steam turbines, at least        partly using steam provided by at least one of said one or more        gas turbines; and    -   providing said compressed hydrocarbon stream by compressing a        hydrocarbon feed stream using at least one or more hydrocarbon        feed compressors driven by said one or more compressor-driving        steam turbines.

Advantageously, said liquefied hydrocarbon stream flows at a rate thatis less than or equal to the flow rate of the hydrocarbon feed streambeing compressed with said one or more feed compressors.

Advantageously, the one or more feed compressors are not incorporated ina refrigerant cycle.

In a further aspect, the present invention provides an apparatus forliquefying a hydrocarbon feed stream, such as a natural gas feed stream,the apparatus at least comprising:

a liquefying system arranged to receive a compressed hydrocarbon stream,the liquefying system comprising one or more cooling stages involvingone or more refrigerant streams, through which cooling stage(s) thecompressed hydrocarbon stream passes to provide one or more warmedrefrigerant streams and a liquefied hydrocarbon stream;

one or more refrigerant compressors driven by one or more gas turbinesto compress at least one of the warmed refrigerant streams;

one or more compressors driven by one or more compressor-driving steamturbines; and

one or more heat exchangers and one or more water/steam streams totransfer heat provided by the one or more gas turbines to at leastpartly drive one or more of the compressor-driving steam turbines,

wherein the one or more compressors driven by the one or morecompressor-driving steam turbines are hydrocarbon feed compressor(s)arranged to receive and compress a hydrocarbon feed stream to providethe compressed hydrocarbon stream.

Advantageously, the liquefaction system is lined-up downstream of theone or more feed compressors and such that the liquefied hydrocarbonstream is provided at a flow rate that is less than or equal to the flowrate of the hydrocarbon feed stream passing through the feedcompressor(s).

The present invention will now be further illustrated by way of exampleonly, and with reference to embodiments and the accompanyingnon-limiting schematic drawings in which:

FIG. 1 is a generalised scheme of part of a liquefaction plant accordingto one embodiment of the present invention; and

FIG. 2 is a more detailed scheme of a liquefaction plant based on thatin FIG. 1.

For the purpose of this description, a single reference number will beassigned to a line as well as a stream carried in that line. Samereference numbers refer to similar components, streams or lines.

It is an object of the present invention to improve the efficiency of aplant or method for liquefying a hydrocarbon stream.

It is a further object of the present invention to reduce the energyrequirements of a plant or method for liquefying a hydrocarbon stream.

The present invention is based on the insight that, of the variouscompressors that are typically present in a hydrocarbon liquefactionplant and process, the hydrocarbon feed compressors, which are arrangedto compress the feed stream before liquefaction, are particularlysuitable for being driven by the steam that is generated using heat ofone or more gas-turbines driving one or more refrigerant compressors ina refrigerant cycle in the liquefaction process.

In balancing the output/load of the refrigerant compressor(s), the steamproduction from the waste heat could at instances be less than usual.When using the steam to drive a hydrocarbon feed compressor, what thenhappens is that the pressure at which the hydrocarbon stream is beingliquefied may sometimes be lower than usual. This, however, has arelatively minor impact on the liquefaction process and on thedistribution of cooling duty over the cooling stages compared to whatwould have been the case if a the steam drives one or more refrigerantcompressors.

Due to the relatively minor impact, there is provided more flexibilityin operating the refrigerant compressor(s) that are driven by the gasturbines that provide the steam.

Because the power required to further compress a hydrocarbon stream tobe liquefied is not as high as that required to compress the refrigerantrequired for the liquefaction process, a surprising benefit of thepresent invention is that more variation in plant design using the gasturbine(s) (depending on their load) can be accommodated in driving thesteam turbine(s). Thus, there is more flexibility in using, morepreferably balancing, the load/output of the refrigerant compressor(s)than has hitherto been possible. This flexibility increases the overallefficiency of a cooling, optionally liquefaction, plant, and cantherefore reduce the energy required.

The method of the present invention also provides the advantage ofcontrolling the pressure under which the liquefaction takes place. Thus,the operator can choose optimal pressure of the compressed hydrocarbonstream to suit subsequent process conditions. In particular, as the oneor more steam turbines are used outside the actual liquefying process,the volume or flow of hydrocarbon stream to be compressed and liquefiedcan be increased compared to conventional liquefaction processes onlyinvolving one or more steam turbines in a refrigeration cycle or circuitthat are driven by steam generated from waste heat of the gas turbinesthat drive the liquefaction process.

The method of the present invention further provides the advantage ofreducing running costs, including fuel consumption, for compression ofthe hydrocarbon stream prior to its liquefaction.

It is noted that U.S. Pat. No. 6,691,531 also relates to a natural gasliquefaction system using gas turbines to drive compressors in a firstrefrigerant cycle, and recovering waste heat from its gas turbines tohelp power steam turbines to drive compressors in a sub-coolingrefrigerant cycle. The refrigerant in this sub-cooling refrigerant cycleconsists of streams that have been separated from the feed stream, suchthat these separated stream are not the feed stream. The feed stream, onthe other hand, is compressed in an inlet compressor.

Steam turbines have not hitherto been used to help compress ahydrocarbon feed stream prior to its liquefaction so as to best manageor balance power in a liquefaction plant.

Moreover, by mixing refrigerant and product streams in the sub-coolingrefrigerant cycle, the system of U.S. Pat. No. 6,691,531 cannot controlpressure of each part or phase.

Said mixing in the system of U.S. Pat. No. 6,691,531, thus brings aproblem that variations in steam provided to the stream turbines drivingthe sub-cooling refrigerant compressors may lead to back flow conditionsof either the inlet compressor or the sub-cooling refrigerantcompressors.

As a consequence of said mixing upstream of the liquefaction condenser,the combined streams are liquefied so that the mass flow rate ofliquefied hydrocarbons upstream of the expansion valve and flash drum isnecessarily higher than the mass flow rate of hydrocarbons beingcompressed in the sub-cooling refrigerant compressors.

In embodiments of the invention, on the other hand, the liquefactionsystem is lined-up with the one or more feed compressors such that theliquefied hydrocarbon stream, upstream of any pressure let down in aflash unit, is provided at a flow rate that is less than or equal to theflow rate of the hydrocarbon feed stream passing through the feedcompressor(s).

Preferably, the compressed hydrocarbon stream after it has beencompressed using the at least one or more feed compressors driven bysaid one or more compressor-driving steam turbines, is not mixed withany compressed stream that has not been compressed with the at least oneor more feed compressors driven by said one or more compressor-drivingsteam turbines.

A plant or method for liquefying a hydrocarbon stream such as naturalgas may involve any number of gas turbines and steam turbines. Forexample, the heat exchanging of the compressed hydrocarbon streamagainst one or more refrigerant streams may involve at least 1-10 gasturbines, such as 2, 3, 4, 5, 6 or 7 gas turbines. One or more of suchgas turbines may be used to compress refrigerant(s) in one or morerefrigerant circuits for cooling a hydrocarbon stream, and one or moreother gas turbines may be involved in one or more other parts,processes, steps or other functions in a plant or method designed toliquefy a hydrocarbon stream such as natural gas. Such other gasturbines may provide the power for other functions or processes such aselectrical power regeneration, whilst providing some steam to help driveone or more steam turbines used in the present invention, or usedelsewhere in a liquefied natural gas plant or method.

One or more of the compressors driven by steam turbines used in thepresent invention may also be partly driven by one or more alternativesources of power or energy.

The gas turbine(s) generally provide steam by heat transfer of their hotexhaust gases against a water line or a water and steam line, so as toincrease the temperature of such a line to create steam at a desiredpressure. Such steam may be used directly by a steam turbine, optionallya dedicated steam turbine, or collected by or at a suitable unit,vessel, point or location, so as to provide management of its timing anddistribution to one or more steam turbines as and when required,especially if there is variation of the load of the steam turbine(s).

One or more refrigerants of the refrigerant circuit may be a singlecomponent such as propane. Alternatively one or more refrigerants aremixed refrigerants based on two or more components, said componentspreferably selected from the group comprising nitrogen, methane, ethane,ethylene, propane, propylene, butanes and pentanes.

In one embodiment of the present invention, a hydrocarbon stream can befully condensed and liquefied by passing it through at least two coolingstages. Any number of cooling stages can be used, and each cooling stagecan involve one or more heat exchangers, as well as optionally one ormore steps, levels or sections. Each cooling stage may involve two ormore heat exchangers either in series, or in parallel, or a combinationof same.

Arrangements of suitable heat exchangers able to cool and liquefy ahydrocarbon stream are known in the art, including for example U.S. Pat.No. 6,389,944 and U.S. Pat. No. 6,370,910.

In one arrangement, this involves the two cooling stages comprising afirst cooling stage and a second cooling stage, the first stage beingpreferably a pre-cooling stage to cool the hydrocarbon stream to below0° C., and the second stage preferably being a main cryogenic stage toliquefy the cooled hydrocarbon stream to below −100° C.

A hydrocarbon stream for use with the present invention may be anysuitable hydrocarbon-containing gas stream to be cooled and liquefied,but is usually a natural gas stream obtained from natural gas orpetroleum reservoirs. As an alternative the hydrocarbon stream may alsobe obtained from another source, also including a synthetic source suchas a Fischer-Tropsch process.

Usually natural gas is comprised substantially of methane. Preferablythe feed stream comprises at least 60 mol % methane, more preferably atleast 80 mol % methane.

Depending on the source, the hydrocarbon stream may contain varyingamounts of hydrocarbons heavier than methane such as ethane, propane,butanes and pentanes as well as some aromatic hydrocarbons. Thehydrocarbon stream may also contain non-hydrocarbons such as H₂O, N₂,CO₂, H₂S and other sulfur compounds, and the like.

If desired, the hydrocarbon stream may be pre-treated before using it inthe present invention. This pre-treatment may comprise removal of anyundesired components present such as CO₂ and H₂S. As these steps arewell known to the person skilled in the art, they are not furtherdiscussed here.

Further the person skilled in the art will readily understand that afterliquefaction, the liquefied hydrocarbon may be further processed, ifdesired. As an example, the obtained LNG may be depressurized by meansof a Joule-Thomson valve or by means of a cryogenic liquidturbo-expander.

The present invention may involve one or more other or furtherrefrigerant circuits, for example in or passing through a first coolingstage. Any other or further refrigerant circuits could optionally beconnected with and/or concurrent with the refrigerant circuit forcooling the hydrocarbon stream.

FIG. 1 shows a general arrangement of part of a liquefied natural gas(LNG) plant 1. It shows an initial hydrocarbon stream 10 such as naturalgas. In addition to methane, natural gas usually includes some heavierhydrocarbons and impurities, e.g. carbon dioxide, nitrogen, helium,water and non-hydrocarbon acid gases. The hydrocarbon stream 10 hasusually been pre-treated to separate out these impurities as far aspossible, and to provide a purified feed stream suitable for liquefyingat cryogenic temperatures. The hydrocarbon stream 10 is typically at atemperature between −20° C. and +80° C., and at a pressure between 30-60bar.

The hydrocarbon stream 10 is compressed by a hydrocarbon feed compressor12 in a manner known in the art. The hydrocarbon feed compressor 12 maycomprise one or more compressors, usually in series. The hydrocarbonfeed compressor 12 is driven by a steam turbine (“ST”) 14, and providesa compressed hydrocarbon stream 20.

The compressed hydrocarbon stream 20 passes through a liquefying system16, which may comprise one or more cooling stages, and each stage maycomprise one or more heat exchangers or other cooling units known in theart. Also passing through the liquefying system 16 is a refrigerantstream 40 adapted to provide cooling to the compressed hydrocarbonstream 20 in order to provide a liquefied hydrocarbon stream 30. Fromthe liquefying system 16, a warmed refrigerant stream 50 is compressedby a refrigerant compressor 18 to provide a compressed refrigerantstream 60, which is then cooled in a manner known in the art, forexample by passage through one or more water and/or air coolers, one ofwhich coolers 24 is shown in FIG. 1.

The refrigerant compressor 18 may comprise one or more compressors, andis driven by a gas turbine (“GT”) 22. In use, the gas turbine 22 createsa gas turbine hot exhaust stream 70, which exhaust stream 70 can bepassed through an exhaust heat exchanger 26. In the exhaust heatexchanger 26, heat from the exhaust stream 70 is transferred to awater/steam stream 80, such that the outflowing gas turbine exhauststream 70 a is cooled, and the water/steam stream 80 is heated toprovide a heated steam stream 80 a, which can then be conducted to thesteam turbine 14 in a manner known in the art to help it drive thehydrocarbon feed compressor 12.

Naturally, it is desired to improve the efficiency of the liquefiednatural gas plant 1, and reduce the energy requirements where possible.However, the demand for the refrigerant compressor 18 can be required tobe different due to expected variation in different process operationsand parameters in different plant designs. This includes variation ofthe cooling duty of the refrigerant due to expected variation in theflow or load of the compressed hydrocarbon steam 20 to be cooled, and/orany operations of the liquefying system 16 not being optimal. Thus,there is variation in the design of the expected duty of the refrigerantcompressor 18, which therefore alters the driving duty of the gasturbine 22, and therefore varies the creation and flow of the hotexhaust gas stream 70. Variation in the flow of the gas turbine exhauststream 70 therefore impacts on the amount of expected steam in thestream 80 a, able to power the steam turbine 14.

The presently disclosed apparatuses and methods provide more flexibilityin using, more preferably balancing, the expected load of therefrigerant compressor 18, and thus the expected production of the gasturbine exhaust stream 70, with the driving of the hydrocarbon feedcompressor 12, than has hitherto been possible. This flexibilityincreases the design efficiency of the overall liquefaction plant 1, andcan reduce the energy requirement expected.

It is known that a refrigerant compressor and a hydrocarbon feedcompressor in a liquefied hydrocarbon plant do not sit in isolation, andare usually linked to other items, units or streams in the plant 1.Thus, where the gas turbine 22 may not provide a sufficient exhauststream 70 to fully power the steam turbine 14, the power for the steamturbine 14 may also be provided from one or more other sources.Similarly, where the gas turbine 22 can provide a greater amount ofexhaust stream 70 than is required to power the steam turbine 14, suchexcess steam or power can be used to help drive another unit and/orgenerate electricity in the plant 1.

However, usually, at least a majority of the power required to drive thesteam turbine 14 is designed to be provided by the gas turbine exhauststream 70, such that flexibility in any variation of the generation ofgas turbine exhaust stream 70 is better accommodated by the steamturbine 14 driving a hydrocarbon feed compressor 12 rather than arefrigerant compressor.

FIG. 2 shows a more detailed scheme of a liquefied natural gas plantbased on that shown in FIG. 1. In FIG. 2, a hydrocarbon stream 10 suchas natural gas firstly passes into a pre-treatment stage 32. Thepre-treatment stage 32 may comprise one or more units adapted to reduce,preferably minimise, non-hydrocarbons from the hydrocarbon stream 10. Atypical such unit is an ‘acid gas removal’ unit, used to reduce levelsof carbon dioxide and hydrogen sulphide, (and possibly other sulphurcompounds).

The pre-treated hydrocarbon stream 10 a therefrom is compressed in ahydrocarbon feed compressor 12, which is driven by a steam turbine 14.The compressed hydrocarbon stream 20 may be cooled by a water and/or aircooler 34, prior to passage through a liquefying system (such as theliquefying system 16 shown in FIG. 1) comprising a first cooling stage 2and a second cooling stage 4.

The first cooling stage 2 involves a first heat exchanger 36 to providea cooled hydrocarbon stream 100. The first cooling stage 2 may compriseone or more heat exchangers, either in parallel, series or both.Typically, the first cooling stage 2 will cool the hydrocarbon stream toa temperature below 0° C., and preferably between −20° C. and −60° C.

The thus cooled hydrocarbon stream 100 is then divided by a streamsplitter 37 in a manner known in the art, to provide first and secondcooled streams 100 a, 100 b. The cooled hydrocarbon stream 100 could bedivided into any number of streams, and FIG. 2 shows the division intotwo streams by way of example only. The division of the cooledhydrocarbon stream 100 could be based on any ratio of mass and/or volumeand/or flow rate. The ratio may be based on the size or capacity of thesubsequent parts of the liquefaction stages or systems or units, or dueto other considerations. One example of the ratio is an equal divisionof the feed stream mass.

The first and second streams 100 a, 100 b pass through a second coolingstage 4 where they are liquefied by two separate liquefaction systems,each generally including at least one heat exchanger respectively, toprovide separate liquefied streams 110 a, 110 b respectively.Liquefaction systems and process conditions for liquefaction are wellknown in the art, and are not described in further detail herein. InFIG. 2, the two liquefaction systems are represented by first and secondmain heat exchangers 38 a and 38 b.

Each of the main heat exchangers 38 a, 38 b in the second cooling stage4 of the example shown in FIG. 2 uses a second refrigerant circuit. Eachof these refrigerant circuits can use a second refrigerant stream (170a, 170 b) with may be formed of the same or a different secondrefrigerant. Preferably, each uses the same refrigerant, and morepreferably the refrigerant is a mixed refrigerant as hereinbeforedescribed. Generally, the first and second gas streams 100 a, 100 b arecooled by the second cooling stage 4 to a temperature of at least below−100° C.

Following use of the refrigerant of each refrigeration circuit in themain heat exchangers 38 a, 38 b, warmed refrigerant streams 150 a, 150 bare withdrawn from the main heat exchangers 38 a, 38 b, and compressedby respective second refrigerant stream compressors 56 a, 56 b, in theform of main refrigerant compressors, which are respectively driven bygas turbines 58 a and 58 b. The compressed refrigerant streams may becooled by one or more water and/or air coolers 161 a/161 b, to providecooled refrigerant streams 160 a and 160 b, which can be further cooledby passage through two refrigerant heat exchangers 62 a and 62 b toprovide further cooled refrigerant streams 170 a, 170 b ready forreintroduction into the first and second main heat exchangers 38 a, 38b.

Hot exhaust gases from the two gas turbines 58 a and 58 b create twoexhaust streams 190 a and 190 b, which pass into secondary heatexchangers in the form of exhaust heat exchangers 76 a and 76 b so as totransfer their heat to water/steam streams passing into the exhaust heatexchangers 76 a and 76 b, to provide heated steam streams 200 a and 200b. These pass into a high pressure (“HP”) collection point 78, which maybe a simple conjunction of lines or conduits, or a reservoir oraccumulator. The HP collection point 78 can provide an outflow steamstream 210 a, which can power the steam turbine 14 in a manner describedhereinabove.

With respect to the two liquefied hydrocarbon streams 110 a and 110 bfrom the main heat exchangers 38 a, 38 b, these can be combined by asuitable combiner 39 to create a combined liquefied stream 110 c, whichenters a gas/liquid separator such as in an end flash unit. An end flashunit typically comprises an expansion means (not shown), such as anexpansion valve (not shown) and/or an expander turbine (not shown),followed by an end flash separation vessel 42. Alternatively it ispossible to expand each of the liquefied hydrocarbon streams 110 a and110 b before combining them in combiner 39.

The end flash unit can generally provide a liquefied hydrocarbon stream120 and a gaseous stream 130. The liquefied hydrocarbon stream 120,which may typically be removed from the bottom of the end flashseparation vessel 42, can be transported via a pump 44 to storage and/ortransportation. The gaseous stream 130, which may typically be removedfrom the top of the end flash separation vessel 42, may be compressed inan end flash gas compressor 48, which may be driven by a steam turbine52. The gaseous stream 130 may provide cooling energy through a heatexchanger 46, prior to being compressed. The compressed end stream 140can then be further cooled by a water and/or air cooler 54 and withdrawnfrom the process for subsequent use.

In one embodiment of the present invention, power for the steam turbine52 driving the end flash gas compressor 48 can also be supplied by steamprovided by the gas turbines 58 a and 58 b for the main refrigerantcompressors 56 a, 56 b. This is shown by steam stream 210 b in FIG. 2,as auxiliarily provided by the HP collection point 78.

Cooling for the heat exchanger(s) in first cooling stage 36 and for thetwo refrigerant heat exchangers 62 a and 62 b may be provided by aseparate refrigerant circuit 6 in which a first refrigerant stream 180is cycled. Refrigerant for the separate refrigerant circuit 6 may be asingle component such as essentially consisting of propane, or a mixedrefrigerant as described hereinbefore. The refrigerant can be providedfrom an accumulator 66, which refrigerant stream 180 therefrom may bedivided into separate streams 180 a, 180 b and 180 c, which pass throughthe heat exchangers listed above, prior to their collection as warmedrefrigerant streams in a collector 68, for instance in the form of acollector drum or a collecting knock-out drum. From the collector 68,the collected streams are compressed by a, separate, first refrigerantstream compressor 72, which can be driven by a third gas turbine 74.

Similar to the actions of the gas turbines 58 a and 58 b describedabove, hot exhaust gases from the third gas turbine 74 may be passed asan exhaust stream 190 c into a secondary heat exchanger 76 c, totransfer heat to a water/steam stream so as to provide a third heatedsteam stream 200 c, which may be passed to the HP collection point 78 toassist contribution of the driving of the steam turbines 14 and 52 asdescribed above.

Thus, the arrangement shown in FIG. 2 has (at least) three gas turbines74, 58 a and 58 b able to provide steam to help drive the steam turbines14 and 52. There is significant flexibility in the use of the steamprovided by the gas turbines 74, 58 a, 58 b, particularly using acollection point 78 which allows management and distribution of thesteam in the most efficient or effective manner to the steam turbines 14and 52. For example, it may be that one or both steam turbines 14, 52may not require to be partly or fully driven at a particular time, suchthat power re-arrangement or re-configuration is easily achievable inthe arrangement shown in FIG. 2. Any excess steam not required by thesteam turbines 14, 52 could be used (via line 240) to provide power toother units or generators in the liquefied hydrocarbon plant 2.

The arrangement shown in FIG. 2 is also able to consider separation ofthe steam (indirectly) provided from each of the three gas turbines 74,58 a and 58 b, such that only one or two of such gas turbines areproviding steam which is useable by the steam turbine 14. For example,it is possible for the gas turbine 74 to be the sole provider of steamfor use in driving the steam turbine 14.

Thus, the present invention has further flexibility in consideringdifferent design arrangements for its gas turbines to provide steam foruse in driving the steam turbine 14. For example, the arrangement shownin FIG. 2 may include one or more further gas turbines in the liquefiednatural gas plant 1 a (to drive other processes or functions) which mayalso provide steam for use in at least partly driving the steam turbine14.

In a further embodiment of the present invention,

FIG. 2 shows use of steam created by the steam turbine 14 to provide anexhaust steam stream 220, which can be collected at a low pressure(“LP”) collection point 82, which point 82 may involve an accumulator orcollector. From the LP collection point 82, generally at low pressure,steam in line 230 can be used to provide heat to regenerate a substanceor material used in the pre-treatment unit 32 in a manner known in theart, e.g. an amine liquid used for the absorption of acid gas. The lowpressure collection point may also be a medium pressure (“MP”)collection point if there exists a further low pressure collectionpoint. Likewise, there may be an optional MP collection point upstreamof the present LP collection point.

Another example of the application of LP (or MP) steam is to providereboiler heat in a fractionation unit that may be present in aliquefaction plant. Thus, further efficiency is achieved in theliquefied natural gas plant by the use of steam turbine exhaust gasrather than extra external power sources. There may be other suitableuses for the LP (MP) stream 230 as well.

The person skilled in the art will understand that the present inventioncan be carried out in many various ways without departing from the scopeof the appended claims.

1. A method of liquefying a hydrocarbon feed stream, the method at leastcomprising the steps of: heat exchanging a compressed hydrocarbon streamagainst one or more refrigerant streams to fully condense the compressedhydrocarbon stream and provide a liquefied hydrocarbon stream and one ormore warmed refrigerant streams; compressing at least one of said one ormore warmed refrigerant stream(s) using one or more refrigerantcompressors driven by one or more gas turbines; driving one or morecompressor-driving steam turbines, at least partly using steam providedby at least one of said one or more gas turbines; and providing saidcompressed hydrocarbon stream by compressing a hydrocarbon feed streamusing at least one or more feed compressors driven by said one or morecompressor-driving steam turbines.
 2. A method as claimed in claim 1,wherein the heat exchanging of the compressed hydrocarbon stream againstthe one or more refrigerant streams involves any number of one to tengas turbines.
 3. A method as claimed in claim 1, wherein the heatexchanging of the compressed hydrocarbon stream against the one or morerefrigerant streams involves at least two cooling stages.
 4. A method asclaimed in claim 3, wherein the at least two cooling stages comprise: afirst cooling stage adapted to cool the hydrocarbon stream to form acooled hydrocarbon stream at a temperature below 0° C. against at leastone first refrigerant stream, which first refrigerant stream iscompressed by a first refrigerant stream compressor driven by at leastone gas turbine; and a second cooling stage adapted to liquefy thecooled hydrocarbon stream from the first cooling stage.
 5. A method asclaimed in claim 4, wherein liquefaction of the cooled hydrocarbonstream in the second cooling stage is carried out by two or moreparallel liquefaction systems, each of which involves at least onesecond refrigerant stream that is compressed by a second refrigerantstream compressor driven by a gas turbine.
 6. A method as claimed inclaim 5, wherein the refrigerant for each second refrigerant stream is amixed refrigerant based on two or more components selected from thegroup comprising nitrogen, methane, ethane, ethylene, propane,propylene, butanes and pentanes.
 7. A method as claimed in claim 4,wherein each gas turbine compressing a refrigerant stream provides steamfor use in driving one or more of the compressor-driving steam turbines.8. A method as claimed in claim 1, wherein said liquefied hydrocarbonstream flows at a rate that is less than or equal to the flow rate ofthe hydrocarbon feed stream being compressed with said one or more feedcompressors.
 9. A method as claimed in claim 1, wherein the compressedhydrocarbon stream after it has been compressed using the at least oneor more feed compressors driven by said one or more compressor-drivingsteam turbines, is not mixed with any compressed stream that has notbeen compressed with the at least one or more feed compressors driven bysaid one or more compressor-driving steam turbines.
 10. A method asclaimed in claim 1, wherein exhaust steam provided by the one or moresteam turbines at least partly provides heat for use in removal of acidgas components in the hydrocarbon feed stream prior to its compression.11. Apparatus for liquefying a hydrocarbon feed stream, the apparatus atleast comprising: a liquefying system arranged to receive a compressedhydrocarbon stream, the liquefying system comprising one or more coolingstages involving one or more refrigerant streams, through which coolingstage(s) the compressed hydrocarbon stream passes to provide one or morewarmed refrigerant streams and a liquefied hydrocarbon stream; one ormore refrigerant compressors driven by one or more gas turbines tocompress at least one of the warmed refrigerant streams; one or morecompressors driven by one or more compressor-driving steam turbines; andone or more heat exchangers and one or more water/steam streams totransfer heat provided by the one or more gas turbines to at leastpartly drive one or more of the compressor-driving steam turbines,wherein the one or more compressors driven by the one or morecompressor-driving steam turbines are hydrocarbon feed compressor(s)arranged to receive and compress a hydrocarbon feed stream to providethe compressed hydrocarbon stream.
 12. A method as claimed in claim 2,wherein the heat exchanging of the compressed hydrocarbon stream againstthe one or more refrigerant streams involves at least two coolingstages.
 13. A method as claimed in claim 12, wherein the at least twocooling stages comprise: a first cooling stage adapted to cool thehydrocarbon stream to form a cooled hydrocarbon stream at a temperaturebelow 0° C. against at least one first refrigerant stream, which firstrefrigerant stream is compressed by a first refrigerant streamcompressor driven by at least one gas turbine; and a second coolingstage adapted to liquefy the cooled hydrocarbon stream from the firstcooling stage.
 14. A method as claimed in claim 13, wherein liquefactionof the cooled hydrocarbon stream in the second cooling stage is carriedout by two or more parallel liquefaction systems, each of which involvesat least one second refrigerant stream that is compressed by a secondrefrigerant stream compressor driven by a gas turbine.
 15. A method asclaimed in claim 14, wherein the refrigerant for each second refrigerantstream is a mixed refrigerant based on two or more components selectedfrom the group comprising nitrogen, methane, ethane, ethylene, propane,propylene, butanes and pentanes.
 16. A method as claimed in claim 5,wherein each gas turbine compressing a refrigerant stream provides steamfor use in driving one or more of the compressor-driving steam turbines.17. A method as claimed in claim 6, wherein each gas turbine compressinga refrigerant stream provides steam for use in driving one or more ofthe compressor-driving steam turbines.
 18. A method as claimed in claim13, wherein each gas turbine compressing a refrigerant stream providessteam for use in driving one or more of the compressor-driving steamturbines.
 19. A method as claimed in claim 14, wherein each gas turbinecompressing a refrigerant stream provides steam for use in driving oneor more of the compressor-driving steam turbines.
 20. A method asclaimed in claim 15, wherein each gas turbine compressing a refrigerantstream provides steam for use in driving one or more of thecompressor-driving steam turbines.